1. Field of the Invention
This invention is directed generally to co-generation, and in particular to improvements therein.
2. Related Art
Efficient power generation represents one of the major challenges of the present generation. Huge power demands require a major effort from the industry, with great implications on world resources and the environment. Clean, efficient power generation methods are being sought by technical groups worldwide.
Co-generation has become one of the preferred choices for small and medium power generation units, due to its increased efficiency and adaptability. The combined gas turbine/steam generation cycle has evident advantages in terms of overall thermodynamic efficiency and also addresses industry power/heat requirements.
Extensive work emphasized in patents and publications has been generated on co-generation. Thus, Sakai et al. (U.S. Pat. No. 4,106,286) propose the concept in FIG. 3 of the present application, together with a de-nitration device placed before the boiler economizer. The boiler described in this patent is a heat recovery type, without additional combustion. In the same category can be placed the work of Haeflich (U.S. Pat. No. 4,572,110). This patent proposes a modification to the boiler, directed towards better emission control. Thus, following the superheater, a catalytic reduction system is implemented for NOx reduction.
Knapp (U.S. Pat. No. 4,414,813) presents a co-generation scheme in which gas turbine feed air is heated not through direct combustion, but via a heat exchanger. Thus, hot flue gases resulting from a bio-mass combustion process are passed through a heat exchanger which heats the compressed air used later in the gas turbine. This process has the advantage of using low quality fuel, but has the disadvantage of introducing a large heat exchanger before the gas turbine. This heat exchanger operates in conditions of high temperature on the side of the flue gases resulting directly from the combustion process, and high pressure on the compressed air side. The high cost of such a heat exchanger may be prohibitive for the implementation of such a scheme. Using a similar findamental approach, Willyoung (U.S. Pat. No. 4,116,005) presents a co-generation concept, where the gas turbine combustor is replaced by a heat exchanger located in the boiler. Thus, instead of having two combustion chambers (one between the gas turbine and the compressor, and the other in the boiler), the installation has only one chamber, in the boiler, where any fuel can be combusted. One of the drawbacks of this invention is the pressure loss in the compressed air heat exchanger, leading to efficiency losses.
Bell (U.S. Pat. No. 4,936,088) suggests a co-generation scheme consisting of a fuel-rich combustion scheme in the boiler, followed by a fuel-lean region to complete the combustion process. This scheme, although seemingly efficient in lowering NOx emissions, complicates the installation design. More recently, Bell (U.S. Pat. No. 5,022,226) extends the co-generation process to an internal combustion engine.
Joy (U.S. Pat. No. 4,594,850) presents a classical co-generation scheme as the one described in FIG. 3, using gaseous fuel.
Moke (U.S. Pat. No. 4,571,949) presents a co-generation scheme where the gas turbine exhaust gases are heated in a duct burner, and used to dry sludge. Following this process, the gases are reheated and sent to a traditional co-generation boiler. One aspect of the invention is the sludge heat exchanger, limited to this application, without the possibility to generalize.
Obermuller (U.S. Pat. No. 4,820,500) proposes a system to purify process gases through an afterburning technology. The gas flow rates are controlled such that the emissions are minimum, and gas concentration and maximum temperature are constant during the process.
Bruhn (U.S. Pat. No. 5,033,414) and U.S. Pat. No. 5,101,772) proposes an apparatus to burn low heating value fuels, and to use an intermediate heat transfer fluid to heat for instance water/steam in a modified boiler. A similar concept is disclosed by Price (U.S. Pat. No. 4,830,093).
Earnest (U.S. Pat. No. 4,204,401) presents a cogeneration cycle as described in FIG. 3 herein, with an additional recirculation of the flue gases exiting the boiler back into the air compressor. This recirculation is designed to improve the gas turbine operation at partial load.
Kobayashi et al. (U.S. Pat. No. 5,419,284) propose a co-generation unit modified boiler design. Thus, the duct burner using the gas turbine exhaust gases, together with an additional burner using additional fuel and air are combined in a single burner, thus reducing the burner/boiler dimensions.
Tomlinson and Cuscino (U.S. Pat. No. 4,354,347) discuss a cogeneration unit involving a heat recovery steam generator. The central concept is to control the flue gas temperature at the boiler outlet, such that it remains higher than the sulfur condensation temperature. Since this temperature is a function of the fuel, a manual or automated process control mechanism must be implemented.
Aguet (U.S. Pat. No. 3,789,804) proposes a scheme where at least two turbines are used to provide oxidizer/heat source for one single boiler. The exhaust from one gas turbine is directed into the boiler bumer, while the other turbine outlet is directed somewhere in the boiler. This design, although having some merit, makes the installation much more expensieve, due to the costs related to two gas turbine installations (compressor, combustor, turbine).
Ashdown (U.S. Pat. No. 4,085,708) presents a burner for a co-generation installation. The oil burner has a primary air duct surrounding the oil pipe, a secondary air section surrounding the primary air duct, and a gas turbine waste duct on the outer circumference of the secondary air. This scheme allows the possibility to use either the secondary air or the waste gases. The primary air is used for flame stability purposes.
Zenkner (U.S. Pat. No. 3,984,196) presents a burner concept for burning waste air. The invention is characterized by a strongly swirled motion, and by the presence of several concentric pipes, for fuel and a portion of the waste air, and for the bulk of the waste air. The fuel and the inner waste air stream create a primary flame which is swirled in one direction, while the outer waste air stream is swirled in the opposite direction.
Vetterich (U.S. Pat. No. 5,558,047) proposes a multi-nozzle bumer array for supplying fuel into the oxidizer. In order to maintain a low temperature process, heat exchangers are laced in the immediate vicinity of the burner, and lower the gas temperature.
Putman et al. (U.S. Pat. No. 5,159,562) propose a linear programming matrix used to represent a combustion process using multiple fuels. The SIMPLEX method is employed to optimize the fuel flows into the boiler.
The co-generation field thus includes different schemes, tailored for different needs and sizes. Some of the more common co-generation schemes can be summarized as follows:
I. Conventional boiler/steam turbine systems:
FIG. 1 presents the conventional steam/electricity co-generation installation, including a boiler generating steam. Fuel 2 enters a boiler 4 (usually with burners and combustion air), producing industrial steam 6 and power steam 8. Power steam 8 is directed to a steam turbine 10 to produce electricity 12. The steam is shared between the industrial needs (Industrial steam in FIG. 1), and the steam turbine generating electricity. The capacity of such a scheme is generally between 10 kW and 400 MW, and it has the advantage of burning a variety of fuels, since the flue gases from the boiler are exhausted in the atmosphere.
II. Conventional combustion turbine systems:
FIG. 2 presents the conventional combustion turbine systems, including a gas turbine providing electric power. Fuel 2 is combusted in turbine 16 to produce electricity 14 and turbine exhaust gases 18. The turbine exhaust gases are fed to a heat exchanger 20 and generate steam 22. The hot exhaust gases exiting the turbine are introduced in a steam generator, and the steam is generally used for industrial purposes. These units have a traditional capacity of 20 kW to 300 MW, and they are generally used in the chemical and petroleum refining industries. For small power requirements, the gas turbine can be replaced with an internal combustion engine. The flue gases are also used to generate steam in the heat exchanger.
III. Combined cycle combustion turbine systems:
FIG. 3 presents the conventional combined cycle combustion turbine systems, including a gas turbine 16 generating electricity 14 (Turbine.sub.g in FIG. 1) and turbine exhaust gases 18. Gases 18 are directed towards a boiler 24, which can operate as a heat exchanger only as presented in FIG. 2, or as a regular boiler, where additional fuel 28 is fired. In this final configuration, the turbine exhaust gases act as a preheated oxidant in boiler 24. Boiler 24 generates steam 26 that can be used for industrial purposes, for electricity generation 30, 32, 34, or combined. The capacity of this scheme varies between 100 kW to several hundred MW. The combined cycle has a high power-to-heat ratio, and it is primarily used in the chemical and petroleum refining industries. This is the scheme making the object of this invention, and an improvement in the overall efficiency and in the cycle operation will be introduced.
Prior work has shown the interest to enhance the power-generation efficiency and improve its operation. This invention addresses both issues. Thus, it is noted that the flue gases exiting the turbine have low oxygen content, traditionally around 12-14%. This is the mam reason why some of the prior art referenced above (U.S. Pat. No. 4,085,708), as well as existing technology, includes at least one jet of air, generally at ambient temperature. This cold air lowers the combustion temperature, and for low heating value fuels such as blast furnace gas or coke oven gas, it degrades the combustion process. By increasing the flue gas volume, the thermal losses and therefore the efficiency of the cycle is reduced. Also, the flue gas volume includes a large amount of "ballast" (nitrogen, water vapor, carbon dioxide) which requires large heat exchange areas, large ducts, etc. FIG. 4 presents the increase in the flue gas volume as the oxygen content decreases (for a fixed amount of oxygen transported through the system). For simplicity, the balance is considered to be nitrogen.
FIG. 4 shows that, as the oxygen concentration in oxidant is lowered to around 13% the volumetric flow rate through the boiler increases by around 60% when compared to the air case. This translates in larger dimensions for the boiler, or alternately higher velocities (meaning higher equipment erosion, higher energy required to transport the flue gases). At the same time, since the water vapor partial pressure in the flue gases is typically higher than in the air, the condensing temperature of the water vapor is higher, and the risk of corrosion increases. By introducing additional air into the boiler system for flame stability reasons, the gas flow rate increases even more. However, by introducing cold ambient air, the flame temperature decreases, and the combustion quality is negatively affected. This negative impact is more important when low quality fuel is used, such as blast furnace gas or coke oven gas. In this case the flame must be supported by a high quality fuel such as natural gas, increasing the fuel costs.
Thus, despite many attempts, there remains a need for improving efficiency and operation of combined cycle co-generation facilities.